Fractured reservoirs containing oil generally consist of two distinct elements: a fracture network and a matrix (for example, a micro porous matrix). The fracture network is a series of interconnected cracks that can transmit fluids easily (very high permeability), but make up only a small fraction of the total porosity. The matrix portion consists of the oil-bearing porous rock that typically exhibits much lower permeability than the fracture network but has the bulk of the total porosity of the reservoir. Hydrocarbon production is normally less efficient in fractured reservoirs. During primary production, the natural reservoir pressures to produce the oil in place quickly decreases, leaving roughly more than 90% of the original oil still left in place, trapped in mostly the matrix (including, for example, micro porous network). Similarly, conventional methods of secondary recovery fail to displace substantial volumes of “left-in-place” oil.
Conventional waterflooding techniques exhibit relatively low efficiency in highly fractured reservoirs. Waterflooding in these reservoirs is characterized by early water breakthrough and rapidly increasing water-oil ratios to an uneconomic level. The injected water tends to travel only through the fractures and not interact with the oil trapped in rock matrix (e.g., micro porous). The injected water cannot penetrate into the matrix and thereby displace and recover oil trapped in the porous matrix. The injected water tends to recover only the oil left behind in the fracture system following primary production. The limited or nonexistent interaction of the injected water with the oil trapped in the matrix is caused also in part by the matrix portion not being water-wet. The matrix will not spontaneously imbibe or take in water. This is largely due to the mobility-tendency of water into high permeability zones and not the low permeability zones (that has most of the oil trapped).
One approach to increase the penetration of a water phase with the oil trapped matrix zones has been to add a surfactant to the water to modify the wettability of the carbonate from oil wet to water wet. Previous research and field experience has demonstrated that including a low concentration of the properly selected surfactant to the water will reduce the interfacial tension and also create now a water-wet condition in the area near the fracture face. With this altered condition, the aqueous phase then penetrates some distance into the porous matrix and thereby pushes out some of the oil that was within the pore spaces. In this countercurrent imbibition process, the oil that is displaced from the matrix then moves into the fracture system. Once pushed into the fracture system, the oil can be moved easily to a production well. In a countercurrent imbibition process, with or without the addition of a water-wetting surfactant, the rate of oil recovery is dependent upon the capillary pressure characteristics of the porous rock matrix. That is, the imbibition process is essentially unaffected by conventional techniques for controlling field operations, such as selecting pressures and flow rates.
Techniques for using surfactants in oil recovery in carbonate formation are disclosed by G. Hirasaki and D. L. Zhang in “Surface Chemistry of Oil Recovery from Fractured, Oil-Wet Carbonate Formations” (2000); by Austad and Standes in “Spontaneous Imbibition of Water into Oil-Wet Carbonates”, Journal of Petroleum Science and Engineering, vol. 39, pp. 363-376, (2003); by W. W. Weiss in “Artificial Intelligence Used to Evaluate 23 Single-Well Surfactant Soak Treatments”, SPE Reservoir Evaluation & Engineering, June 2006; U.S. Pat. Nos. 2,792,894; 4,364,431; 4,842,065; 5,247,993; and U.S. Published Patent Application No. 2007/0215347 A1.
Another approach is to use gas flooding techniques such air, CO2, natural gas flooding, or any combination thereof, which is a form of enhanced oil recovery (EOR). Generally, CO2 EOR is where CO2 gas is pumped/injected into an injection or production well to an underground formation (e.g., fracturing reservoir) and, under certain physical conditions, miscibly mixes with trapped or left-in-place oil. This allows the left-in-place oil to become more easily displaced into the high permeability zones and recovered. The CO2, at high pressure and reservoir temperature, miscibly mixes with the oil to form a low viscosity fluid that can be more easily mobilized. Additionally, CO2 has the capability of invading zones not previously invaded by water, as well as releasing and reducing trapped oil. The mixed residual oil and gas can also be displaced by a chase phase, for example, with water in a WAG (Water Alternating Gas) process.
Nitrogen and flue gas flooding (non-hydrocarbon gasses) can likewise be utilized. Nitrogen, however, has a low viscosity, poor miscibility with oil, and requires a much higher pressure to generate or develop miscibility as compared with CO2 flooding. As such, nitrogen and flue gas flooding are generally utilized as a “chase gas” in hydrocarbon-miscible and CO2 gas flooding (i.e., nitrogen or other low-cost gasses being used to provide a gas drive whereby a significant portion of the reservoir volume is filled with such gasses). However, while nitrogen can be used as a chase gas, it is understood that nitrogen and/or flue gas can be utilized in any gas flooding technique described herein.
As explained above, a fractured reservoir is extremely heterogeneous and has zones of high permeability in close proximity to zones of low permeability. Thus, CO2 and similar gas flooding techniques—analogous to some water flooding techniques—suffer from the tendency of the injected gas sweeping oil from only a limited area of the reservoir, i.e., from zones of high permeability. This occurs in part because the viscosity of CO2 at reservoir conditions is much lower than that of most oils, which will limit the sweep efficiency of the displacement and, therefore, oil recovery
Thus, an approach to increase the penetration of a gas within the matrix blocks containing trapped oil has been to inject foam under pressure into the oil-bearing formation. The foam is generally formed by aeration of a mixture of surfactant and water. The foams having high apparent and increased viscosity will reduce the mobility of the water/surfactant solutions into the large fractures or high permeability zones effectively closing them off and/or providing a barrier to entry. With the altered condition, a subsequently introduced gas (such as CO2, natural gas) is diverted and/or able to penetrate into the low permeability porous matrix. In some particular embodiments, the reservoir is not a fractured reservoir, but an oil-bearing reservoir having naturally occurring zones of high permeability and naturally occurring low zones of permeability.
A problem with the use of foams in gas mobility control, however, is the inherently short life of the foams. For example, in oilfield applications, the foams dissipate relatively quickly diminishing the effectiveness in blocking the high permeable large fractures and any enhancement in oil recovery. It would be desirable to have a method for enhancing the stability of foam in aqueous applications such as in oilfield applications.